Progressive cavity or Moineau-type downhole motors have been used for many years in the drilling of oil and gas wells. The construction and operation of such devices is exemplified by U.S. Pat. Nos. 2,892,217 to Moineau (1932); 3,840,080 to Berryman (1974); 4,080,115 to Sims et al. (1978); 4,329,127 to Tschirky et al. (1982); 4,632,193 to Geczy (1986); and 4,679,638 to Eppink (1987). These devices have a single shaft in the shape of one or more helices contained within the cavity of a flexibly-lined housing. The generating axis of the helix constitutes the true center of the shaft. This true center of the shaft coincides with its lathe or machine center. The lined cavity is in the shape of two or more helices (one more helix than the shaft) with twice the pitch length of the shaft helix. One of the shaft and the housing is secured to prevent rotation; the part remaining unsecured rolls with respect to the secured part. As used herein, rolling means the normal motion of the unsecured part of the progressive cavity device. In so rolling, the shaft and housing form a series of sealed cavities which are 180.degree. apart. As one cavity increases in volume, its counterpart cavity decreases in volume at exactly the same rate. The sum of the two volumes is therefore constant.
By pumping high pressure drilling fluid or "mud" into the cavity at one end of the progressive cavity device, the rotor can be caused to rotate so as to cause a progression of cavities which eventually allows the fluid to exit the progressive cavity device. As long as there is a significant fluid pressure drop across the progressive cavity device, the rotor will roll within the stator.
The rolling motion of the rotor is actually, quite complex in that it is simultaneously rotating and moving transversely with respect to the stator. One complete rotation of the rotor will result in a movement of the rotor from one side of the stator to the other side and back. The true center of the rotor will, of course, rotate with the rotor. However, the rotation of the true center of the rotor traces a circle progressing in an opposite direction to the direction of the rotor, but with the same speed (i.e., reverse orbit). Thus, the rotor driving motion is simultaneously a rotation, an oscillation and a reverse orbit.
Because of the complex nature of the rotor movement, the progressive cavity device must include a coupling if it is to be used to drive a drilling shaft. Generally, a universal joint coupling is used to convert the complex rotor motion into rotation of the drilling shaft. It is believed that improved results are provided by progressive cavity devices of the type described in applicant's copending application Ser. No. 07/420,019 filed Oct. 11, 1989 entitled "Progressive Cavity Drive Train". In any case, when used to drive a drilling shaft, a progressive cavity drive train must include at least a rotor, a stator and a coupling.
Progressive cavity downhole drilling apparatus also typically include a housing connected to a conventional drill string composed of drilling collars and sections of drill pipe. The housing includes a passageway through which high pressure fluid can be communicated to the inlet of the progressive cavity device. The drill string extends to the surface where it is typically connected to a kelly mounted in the rotary table of a drilling rig.
The rotor is coupled to a rotary drill shaft mounted in and extending from the bottom of the housing. At its lower end, the drill shaft is connected to a drill bit. The weight of the drill string is transmitted to the drill shaft to assist in breaking up hard formations when the drill shaft is rotated. To relieve the otherwise extreme frictional drag between the drill shaft and the housing, bearings are provided between the housing and the drill shaft.
The high pressure drilling fluid or "mud" is pumped through a first passageway down through the drilling string into the progressive cavity drive train. As the drilling fluid is pumped down through the stator, the rotor is rotated, driving the drill bit. The drilling fluid flows past the progressive cavity drive train coupling and is then directed to an interior passage of the drill shaft where it exits through several nozzles in the drill bit, acting to remove debris by carrying it to the surface. The high pressure fluid then flows from the bottom of the hole to the surface through an annular space between the drilling string and the wall of the bore hole.
Since the drilling fluid and its contaminants can be hostile to the function and life of the bearings, it is desirable to eliminate or control the flow of drilling fluid through the bearings. In most progressive cavity devices, seals have been used to direct the drilling fluid into the interior passage of the drill shaft. As indicated above, this is necessary in order to channel the drilling fluid through the drill bit. The provision of flow diverting seals can also eliminate the drilling fluid from the bearings, permitting oil lubrication to extend bearing life. However, there are problems with such designs. One such problem is caused by the fact that there is a tremendous (in the range of 500 p.s.i. to 2,000 p.s.i.) pressure differential across the seal. Moreover, it is necessary to provide a separate source of lubricant for the drilling shaft bearings. The required pressure equalization means and reservoirs complicate design, creating functional problems which increase initial and maintenance costs. Also, effective seals often create torque losses and expensive repairs result when failures occur.
Another approach has been to use the drilling fluid to lubricate the shaft bearings. In such constructions, a flow restrictor is used, instead of a seal, to direct fluid into the interior of the drilling shaft. The flow restrictor diverts most of the fluid into the drilling shaft, but when properly controlled, a small percentage of the drilling fluid is allowed to pass and to lubricate and cool the radial and thrust bearings prior to entering the drill bit. The amount of drilling fluid that passes through the bearings is controlled by the flow restrictor. In the past, the flow restrictor has typically been a separate member. Often, it consisted of a series of close-fitted hardened rings or a mechanical face seal. It has been found that control of drilling fluid flow through the bearings is less expensive to maintain and less subject to catastrophic failure than elimination of flow via seals.
The present inventor has discovered that certain radial bearings which he previously invented also provide a flow restricting function when used to support a drilling shaft. The use of these bearings as combined flow restrictors and radial supports has yielded superior results at far less cost than conventional flow restrictors. These bearings are described in U.S. Pat. Nos. 4,515,486 and 4,526,482. Similar attempts to provide flow restrictors having support functions have been made in other fields. For example, U.S. Pat. No. 3,456,746 to Garrison discloses bearings having a brass support with a rubber or plastic sleeve which is provided with longitudinal grooves extending the length of the bearing.
While constructions such as the present inventor's previous patented bearing construction have been employed as flow restrictors in some applications, problems have arisen in using these bearings in high-flow, high-pressure drop drills which have recently been introduced. The total hydrostatic pressure head in such devices is in the range of 20,000 to 50,000 p.s.i. The pressure drop across the drill bit of one of these new drills may be as high as 1,000 to 2,000 p.s.i. As a result of this large pressure drop across the bearing, the fluid which is allowed to pass through the flow restrictor moves at a tremendous velocity. This high velocity on the order of (100 ft/s) results in turbulent flow which erodes the bearing grooves after only several hours of operation. It is known that the flow velocity through the channels in the flow restrictor is a function of both the length and size of the channels. Thus, in prior lower-pressure applications, large longitudinal grooves in the bearing were able to keep flows in the laminar region. However, in order to accommodate new high pressure drop applications, such bearings would have to be much larger (about 10 times longer) than currently used. This would dramatically increase the cost of manufacture and use.
Finally, it should be noted that journals with helical channels are also known. U.S. Pat. No. 1,733,416 to Lebesherdis teaches a combination bearing and sealing shaft having a helical groove which is externally provided with lubricating fluid. The helical groove is not intended for flow restriction. U.S. Pat. No. 1,961,029 to Benedek discloses a hydrodynamic bearing with a helical groove. Use of this bearing for flow restriction in high pressure environment is neither disclosed nor suggested. Finally., U.S. Pat. No. 2,397,124 to Buffington et al. discusses a hydrodynamic bearing with two opposing broad helical grooves. The use of the bearing for flow restriction was not recognized.